Term Paper for Industrial Air Pollution Control - Air Pollution Issue for Oil Sands Industry in Alberta

Term Paper for Industrial Air Pollution Control - Air Pollution Issue for Oil Sands Industry in Alberta
Civil Engineering and Applied Mechanics Department

Abstract

The rapid expansion of the oil sands is driving up the pollution emitted in Alberta. Challenges in managing emissions in oil sands industry will become greater with time. Air emissions from oil sands operations include carbon dioxide, sulphur dioxide, nitrogen oxides, hydrogen sulphide carbon monoxide, methane and other volatile organic compounds, ozone and particulate matter. There are growing social and regulatory pressures to reduce the overall environmental footprint of the industry. Alberta Energy and Utilities Board and Alberta Environment are main regulatory agencies responsible for the sustainable development of oil sands.
Oil sands producers have achieved significant progress in emission intensity through ongoing research and development programs, equipment modifications and replacement, and improved operating procedures. Oil sands industry is high energy-intensive. Oil sands producers are included in the federal government’s Large Final Emitter (LFE) system. Energy intensity and GHG emissions intensity in oil sands industry have been reduced through comprehensive efforts in last decade. One of the biggest challenges facing the industry is the increase in total emissions and cumulative impacts levels of air emissions.

Introduction
The rapid expansion of the oil sands is driving up the pollution emitted in Alberta. Alberta led the country in releases of air pollutants. In 2003, more than 1 billion kilograms of pollutants were dumped into the air, including criteria air contaminants (CACs) and toxic contaminants (Environment Canada and PollutionWatch, 2003). Oil sands operations contributed large volumes of CACs, including nitrogen oxides (NOx), sulphur dioxide (SO2), volatile organic compounds (VOCs) and particulate matter (PM), according to Environment Canada’s CAC Emissions summaries. Significant progress has already been achieved through industry’s response to the Voluntary Challenge & Registry (VCR) initiative (Alberta Chamber of Resources). Industry’s use of low NOx burners and flue gas desulphurization to reduce SO2 emissions has lowered the emission intensity to produce synthetic crude oil, but the emission intensity of oil sands production for common pollutants remains higher than that of conventional oil production (the Pembina Institute). Concerns over the ratification and compliance with the Kyoto Protocol in Canada and climate change issues have pushed the environmental issues of the oil sands industry to the forefront. The major greenhouse gases (GHG) emissions for the oil sands are carbon dioxide (CO2), methane (CH4), and nitrous oxide ( N2O). The addition of the three factors is referred to as CO2 ”equivalent”, or CO2E. CO2 accounts for 85% -95% of the total effect in oil sands industry. Oil sands development in Alberta is regulated by both the Alberta Energy and Utilities Board (AEUB) and Alberta Environment (AENV). There are growing social, environmental and regulatory pressures to reduce the environmental footprint of the industry. The scope of this review is industry background, profiles of emissions, regulatory context and control practices and technologies. Challenges facing the industry are also discussed.

Industry Overview
Canadian’s oil sands contain estimated 175 billion barrel of oil that is economically recoverable. The reserves are second largest to Saudi Arabia. The majority of Alberta’s crude oil reserves are located in three geological regions: Athabasca, Cold Lake, and Peace River. The three largest oil sands companies, Syncrude, Suncor and Albian, develop oil sands heavily in Athabasca. Unlike Sandi crude, northern Alberta’s oil is not under sands, but it is wrapped around sands. There are more steps involved in producing synthetic crude oil from oil sands. Oil sands can be developed using surface mining or in situ method, depending on the depth of the reserves. To be surface mined, the deposit must be less than 100 metres from the surface. Approximately four tonnes of material (two tonnes of soil and rock above the deposit and two tonnes of oil sands) must be mined to produce one barrel (159 litres) of synthetic crude oil ( Syncrude).

In Alberta, about 80% reserves can only be recovered with in situ techniques. On average, in situ techniques require four times as much natural gas as surface mining. The in-situ techniques currently in use employ steam to heat the bitumen, allowing it to flow into a well and to be produced to the surface. The two most common methods of in-situ production are cyclic steam stimulation and steam assisted gravity drainage ("SAGD"). The steam used in both processes is normally generated using natural gas, and natural gas is the primary input cost of both methods. SAGD is a newer, more efficient method of in-situ bitumen recovery in the Athabasca oil sands region and is expected to be used for virtually all new projects in that area. Bitumen extraction is followed by primary (coking) and secondary (catalytic hydrotreating) upgrading processes in order to get synthetic crude oil (SCO). SCO is further refined in specially designed or slightly modified conventional refineries into transportation fuels. Large amount of energy is utilized and various of air pollutants are produced during the operation of mining, separation and degrading. Oil sand production is expanding rapidly. It is expected to increase by about 1.7 million b/d over the next decade from its current level of roughly one million barrels per day. Oil sands currently make up about half of all production of Canadian oil. By 2015, oil sands will grow to three quarters of all production. The goal for 2030 is 5 million barrels per day.

Profile of Emissions

CAC emissions
Oil sands producers are included in Canadian government’s Large Final Emitters (LFEs) categories. In 2003, Syncrude and Suncor’s facilities were ranked number one and two respectively as Alberta’s largest emitters of CACs. Similarly, their facilities ranked fifth and eleventh among the most polluting facilities in Canada (PollutantWatch, 2005). The anticipated growth of air pollution from oil sands development promises to keep Alberta ranked number one in Canada for air pollution for decade, with more oil sands facilities likely to join the national Top 20 list of polluting facilities ( the Pembina Institute).
CACs have significant effects on both human health and the environment. NOx irritates the lungs and increases susceptibility to respiratory infections. SO2 at high levels can cause premature death, increased respiratory symptoms and disease, decreased lung function as well as alternations in lung tissue and structure. Particulate matter can be carried deep into the lungs. It has been linked with heart and lung problems such as asthma, bronchitis and emphysema. Individual VOCs can be toxic to humans (the Pembina Institute). Not only are there concerns regarding the atmosphere but also acid deposition in rain, snow and dust, as well as ground level smog.

> Sulphur dioxide emissions come from cokers, sulphur plant tail gas incinerators, and from any energy combustion, including vehicles. About 86 percent of the SO2 releases through the main stack originated in the fluid coking process used to upgrade bitumen into crude oil (Syncrude). To a lesser extent, releases can originate from the hydrocracking and hydrotreating operations which decrease the sulfur and nitrogen content in crude oil. While vehicular SO2 emissions are not the subject of direct relevance to the oil sands industry, ultra low sulphur fuels being legislated into use by 2007 will reduce emissions from this source. SO2 is one of the three major contributors to acid rain.

> Nitrogen oxides are another contributor to acid rain. Nitrogen oxide emissions are associated with a wide range of activities, including vehicle emissions, oil sands mining and the burning of fuels during oil processing and upgrading. Since the industry has moved to low-NOx burners, more concerns are given to NOx emissions from diesel trucks in the mining sector.

> Volatile organic compounds can be from multiple sources of ‘fugitive’ emissions (valves, gasketted joints, tanks etc.), which can be reduced through active preventative maintenance. Mining ponds are much more of a challenge, where the VOCs are present in the large tailings streams after froth recovery via naphtha or other solvents.

> Ozone is a contributor to smog. It is largely formed by sunlight catalyzed reactions between oxygen and NOx and VOCs.

> Particulates are predominantly from diesel exhaust in the mining operations, and from reactions between air and NOx (main stacks and diverter stacks) and VOCs. Both particulate sources are contributors to smog.

> Odours occur occasionally, due to an unforeseen plant upset. Fugitive emissions of VOCs and reduced sulfur compounds result from releases from process-affected water containment areas, tank venting and process equipment leaks from various operating units.

Greenhouse Gases
Oil sands industry is high energy-intensive. Production of a barrel of synthetic crude oil from oil sands generates more than three times more GHG emission than production of a conventional light or medium crude oil ( the Pembina institute ). The oil sands are the single largest contributor to GHG emissions growth in Canada. While the emissions intensity of producing oil sands has decreased by 26% over the past decade, the rapid rate of new development has more than consumed these gains (Government of Canada). In 1997, the upstream fossil fuel producing industry accounted for 98 megatonnes (Mt) of GHG emissions, of which 16% (16 Mt) was emitted from oil sands operations. In 2003, oil sands industry emitted 25.2 Mt CO2E, or 3.4% of Canada’s total emissions (740 Mt). According to the Pembina Institute, emissions from the oil sands will rise, by 2010, to 7.5–8.2% of Canada’s business-as-usual emissions (830 Mt) in that year, or 11.0–12.1% of Canada’s annual average Kyoto target emissions (560 Mt) during 2008–12. They also show that oil sands contribute 41–47% (36.7–42.7 Mt) of the projected business-as-usual growth (90 Mt = 830–740 Mt) in Canada’s total annual emissions between 2003 and 2010.

At operation, the source of CO2 releases is from the combustion of liquid and gaseous fuels and waste gases, including natural gas, refinery fuel gas, coker burner overhead gas, diesel, gasoline and propane. In addition, the natural gas is used in hydrogen plants to produce hydrogen for upgrading bitumen. During the hydrogen production process, CO2 is formed and released into the atmosphere. CO2 is also produced off-site during the generation of power imported.

Regulatory Perspective
Legislation
Federal, provincial and municipal governments each have a role in the sustainable development of natural resources. The federal legislation most applicable to environmental protection and resource development in Oil Sands Area is Canadian Environmental Assessment Act (CEAA) and Canadian Environmental Protection Act (CEPA). The government of Alberta is the primary regulator of oil sands development. Alberta energy and utilities Board (EUB) is the primary decision maker regarding proposed projects. Alberta Environment (AENV) is responsible for granting regulatory approvals and licenses for air emissions, water withdrawals and land disturbance. The provincial legislation and other tools most applicable to sustainable development in the Oil Sands region are Environmental Protection and Enhancement Act (EPEA) and Oil and Gas Conservation Act. EPEA provides for the protection of the environment through seven core strategies: (1) Project Assessment/Evaluation, (2) Approvals, (3) Monitoring, (4) Enforcement, (5) Pollution prevention, (6) Standards, objectives, and guidelines, and (7) Decommissioning and reclamation.

Policies and Guidelines
To better manage cumulative environmental impacts of oil sands development, in 1998, Alberta Environment (AENV) committed to leading the creation of the Regional Sustainable Development Strategy (RSDS) for the Athabasca Oil Sands area. The RSDS builds on Alberta's current environmental and resource management system by creating the framework that will adapt to the changing needs of the area, which will guide government’s environmental and resource managers and identify priority regional environmental issues, and to organize the science and monitoring work needed to understand these issues.

Particularly, Alberta Environment (AENV) and the Alberta Energy and Utilities Board (AEUB) jointly released ID 2001-3 Sulphur Recovery Guidelines for the Province of Alberta in 2001. The guidelines and requirements set out in this directive became effective January 1, 2002 and replaced IL 88-13 Sulphur Recovery Guidelines - Gas Processing Operations (1988). The revised guidelines have started to and will continue to have significant implications on production, costs and stakeholder relationships for the oil sands industry in Fort McMurray, Alberta.

Oil sands production is included in the federal government’s Large Final Emitter (LFE) system, under which companies will face mandatory GHG intensity targets during the period 2008–12. Targets will be set for existing facilities at 15% below projected business-as-usual (BAU) emissions intensity for the year 2010 for all emissions except “fixed process emissions,” for which targets will be set equal to BAU levels (The Climate Implications of Canada’s Oil Sands Development, 2005).

Emission Reduction Practices and Technologies
Oil sands developers are taking advantage of new opportunities and technologies as well as synergies in their operations to improve the environmental performance of their projects and create positive changes in nearby communities (National Energy Board). While absolute emissions have increased or remained constant as a result of growth in oil sands, the eco-efficiency (impact per unit of energy produced) of operations and emission intensities continue to improve through ongoing research and development programs, equipment modifications and replacement, and improved operating procedures.

SO2: Between 1995 and 2000, most emissions from oil sands operations increased. This is a result of increased production, although environmental improvements curtailed the increase to some degree. A notable exception was a sharp decline in SOx emissions. This drop came about as a result of the installation of a flue gas desulphurization (FGD) unit at Suncor and operational improvements at Syncrude between 1996 and 2000. To meet the sulphur guideline IL 2001-3, Suncor and Syncrude have been using two-stage Claus units and three-stage Claus units respectively for the implementation of sulphur recovery. Substantial sulphur emission reduction benefits has also achieved through new process equipment such as hydrocraker, which, unlike the cokers, processes bitumen without burning coke, and improved operating procedures and equipment performance, such as improving sour water stripping capacity and modifying our cokers to reduce coke particle carry-over and coke burn in the CO Boilers, which cause sulfur emissions.

NOx: Oil sands industry have optimized boiler operations to improve fuel efficiencies, thereby lowering NOx emissions. Emissions are also reduced through the use of improved combustion equipment, including low NOx burners. Fuel switching is an alternative to reduce NOx releases from diesel trucks. Running diesels on natural gas will reduce NOx by about 40%.

H2S: Improvement of CO Boiler reliability has reduced diverting incidents and H2S releases. And new sulfur degassing facilities which, combined with the sulfur recovery units, has reduced the H2S content of blocked sulfur on site from 300 parts per million by weight (ppmw) to an average of 50 ppmw. Work is now underway to reduce that content to 30 ppmw.

Stemming Leak: Efforts to reduce fugitive emissions are based on comprehensive surveys of emission sources and constituents. Two vapour recovery systems are constructed to collect vapours from tanks and vessels: nitrogen vapour recovery system, which is connected to those process areas with volatile materials; and the natural gas vapour recovery system, which is connected to areas with less volatile materials. Oil sands producers have developed naphtha recovery unit to recover these light hydrocarbons from the tailings and to reintroduce it into the extraction process. Since the unit's commissioning, Syncude has cut naphtha losses by more than 75 percent. Equipment maintenance and repair is critical to control fugitive emissions from piping. To help minimize these emissions, the industry has a number of thorough initiatives under the umbrella of the Leak Detection and Repair Program. These include pressure safety valve maintenance, pump seal repair, and calibration and maintenance of control systems.

Particulate Matter: Particulate emissions from the main stack are controlled by a particulate removal system which includes equipment within the cokers and the coke silos. This limits coke carry-over from the cokers. The system also includes the electrostatic precipitators (ESP) and hydroveyors which remove 95 percent of the remaining particulate found upstream of the two CO Boilers. Particulate emissions can be reduced by reducing solids carryover from the coke silos and coker burner to the electrostatic precipitators, improving the reliability and efficiency of the precipitators, and improving system monitoring.

Odour: The industry addresses odor issues by installing equipment such as vapor recovery systems on oil storage tanks. It also inspects and maintains equipment such as valves and flanges (Alberta Energy and utilities Board). Odour incidents are minimized through reduced use of CO Boiler diverter stacks and improved reliability of the naphtha recovery unit and tank vapour recovery systems, and reduced sewering of sour water and sour hydrocarbon streams.

GHG Emissions: Continuous reductions of energy intensity and thus GHG emissions intensity in oil sands industry have been achieved through improved plant reliability; increased waste heat recovery during the extraction process; energy improvements in the extraction process; improved yield from the process units; and a number of minor equipment and procedural efficiencies. Energy consumption per cubic metre of production has been steadily reduced. Using technological enhancements, oil sands operators are expected to reduce their energy requirement by 45 per cent below 1990 levels by 2010. Several innovative technologies, including Steam Assisted Gravity Drainage (SAGD), Vapour Extraction Process, or VAPEXTM, and THAI/CAPRI, have been developed. Modifications to SAGD to allow it to run at lower pressures and temperatures, and thus lower gas-to-oil ratios and demand for gas, has some potential in reservoirs suited to low pressure operations. VAPEXTM is a promising recovery technology that involves the injection of solvents, instead of steam, into the reservoir to reduce the viscosity of the bitumen and allow it to flow to the well bore. The advantage of this process is that natural gas is not required to produce steam thus providing a savings on energy usage. The proposed THAI process is designed with a vertical injection well and a horizontal producing well, with air injected into the reservoir to support combustion of the bitumen in situ. The heat generated reduces the viscosity of the bitumen allowing it to be produced.
Activity GHG intensity(kg CO2 E /barrel)
Mining of bitumen 35
Cyclic production of bitumen 90
SAGD production of bitumen 55
THAI production of bitumen 65
Upgrading of bitumen 45

CO2 sequestration is at the top of the list of future solutions. Included this solution are not only non-productive storage in depleted oil and gas reservoirs, or in aquifers, but also the use of CO2 for enhanced oil recovery or cola bed methane production. Sequestering is only feasible today for more concentrated, and easily consolidated sources of CO2. More R&D is required.

Challenges and Problems
As the industry has made strides in managing air emissions, but it continues to be challenged because of the scale of growth. The net increase in total emissions and cumulative impact levels is common to air emissions, land disturbance and water use for oil sands industry, although significant intensity improvements have been achieved through the introduction of new technologies and more efficient operating processes.
Another problem is technological dilemma. Sometimes a technology that solves one problem creates other challenges that we need to address. That is the case with in-situ technology to recover bitumen that cannot be accessed through conventional oil sands mining. In-situ involves drilling into the oil sands reservoir and then injecting steam that heat the thick bitumen and allow it to flow to the surface. Recovering bitumen with less land disturbance than conventional mining techniques. However, in-situ is energy-intensive. We must burn a lot of natural gas to generate enough steam to heat the bitumen. urthermore, oil sands developers are under pressure to find ways to mitigate environmental impacts. Stricter environmental guidelines and regulations, oil sands companies could increase the production cost of oil and hamper new development in the sands.

Concluding Remarks
As oil sands development in Alberta is poised to enter a periods of unprecedented growth and expansion, there are a number of issues and challenges facing operators. The oil sands operations emit large amounts of carbon dioxide and criteria air contaminants. The reduction of air emissions is one of the most complicated and pervasive issues. The cumulative effects of the oil sands projects are beginning to be considered collectively and in a coordinated manner. Through huge investment on best available technologies and comprehensive improvements of equipment and procedures, oil sands companies have achieved emission intensity improvements substantially. However, the pressure increases to address the environmental implications as the rapid growth of the industry is driving up the total pollution emitted.

References:

Canadian Crude Oil Production and Supply Forecast 2005 – 2015, Canadian Association of Petroleum Producers, 2005